Monday, September 16, 2019

Tight Oil

In addition, oil from tight sandstone and from shale formations is another type of crude oil which varies from a gas-condensate type liquid to a highly volatile liquid.

Tight oil refers to the oil preserved in tight sandstone or tight carbonate rocks with low matrix permeability- in these reservoirs, the individual wells generally have no natural productivity or their natural productivity is lower than the lower limit of industrial oil flow, but industrial oil production can be obtained under certain economic conditions and technical measures. Such measures include acid fracturing, multistage fracturing , horizontal wells, and multilateral wells. 

The term light tight oil is also used to describe oil from shale reservoirs and tight reservoirs because the crude oil produced from these formations is light crude oil. The term light crude oil refers to low-density petroleum that flows freely at room temperature and these light oils have a higher proportion of light hydrocarbon fractions resulting in higher API gravities (between 37 and 42 degrees) (Speight, 2014a). However, the crude oil contained in shale reservoirs and in tight reservoirs will not flow to the wellbore without assistance from advanced drilling (such as horizontal drilling) and fracturing (hydraulic fracturing) techniques. 

There has been a tendency to refer to this oil as shale oil. This terminolgy is incorrect insofar as it is confusing and the use of such terminology should be discouraged as illogical since shale oil has been the name given to the distillate produced from oil shale by thermal decomposition. 

There has been the recent (and logical) suggestion that shale oil can be referred to as kerogen oil (IEA, 2013).

Monday, September 9, 2019

Tight Gas

In respect of the low permeability of these reservoirs, the gas must be developed via special techniques including stimulation by hydraulic fracturing (or fracking) in order to be produced commercially.

 Conventional  gas typically is found in reservoirs with permeability >1 mD and can be extracted via traditional techniques. A large proportion of the gas produced globally to date is conventional, and is relatively easy and inexpensive to extract. In contrast, unconventional gas is found in reservoirs with relatively low permeability (<1 mD) and hence cannot be extracted via conventional methods. However, there several types of unconventional gas resources that are currently under production but the three most common types are (1) shale gas, (2) tight gas, and (3) coalbed methane although methane hydrates are often included with these gases under the general umbrella of unconventional gas.

Generally, shale gas is a natural gas contained in predominantly fine, low-permeable sedimentary rocks, in consolidated clay-sized particles, at the scale of nanometers. Gas shale formations are organic-rich formations that are both source rock and reservoir. 

The expected value of permeability to gas flow is in the range of micro- to nanodarcy. The gas retained in such deposits is in the form of adsorbed material on rock, trapped in pore spaces and as an interbedding material with shales. Although the shale gas is usually very clean, it is hard to recover from deposits because of the structural complexity and low hydrodynamic conductivity of shales.

Shale gas is part of a continuum of unconventional gas that progresses from tight gas sand formations, tight gas shale formations to coalbed methane in which horizontal drilling and fracture stimulation technology  can enhance the natural fractures and recover gas from rocks with low permeability. Gas can be found in the pores and fractures of shales and also bound to the matrix, by a process known as adsorption, where the gas molecules adhre to the surfaces within the shale. During enhanced fracture stimulation drilling technology, fluid is pumped into the ground to make the reservoir more permeable, then the fractures are propped open by small particles, and can enable the released gas to flow at commercial rates.  By drilling multilateral horizontal wells followed by hydraulic fracturing, a greater rock volume can be accessed.

More specifically, shale gas is natural gas that is produced from a type of sedimentary rock derived from clastic sources often including mudstones or siltstones, which is known as shale. Clastic sedimentary rocks are composed of fragments (clasts) of preexisting rocks that have been eroded, transported, deposited, and lithified into new rocks. Shales contain organic material which was lain down along with the rock fragments. 

In areas where conventional resource plays are located, shales can be found in the underlying rock strata and can be the source of the hydrocarbons that have migrated upwards into the reservoir rock. Furthermore, a tight gas reservoir is commonly defined as is a rock with matrix porosity of 10% or less and permeability of 0.1 mD or less , exclusive of fracture permeability. 

Shale gas resource plays differ from conventional gas plays in that the shale acts as both the source for the gas and alsto the zone (also known as the reservoir) in which the gas is trapped. The very low permeability of the rock causes the rock to trap the gas and prevent it from migrating toward the surface. The gas can be held in natural fractures or pore spaces, or can be adsorped onto organic material. With the advancement of drilling and completion technology, this gas can be successfully exploited and extracted commercially as has been proven in various basins in North America.

Aside from permeability, the key properties of shales, when considering gas potential, are total organic carbon (TOC) and thermal maturity. The total organic content is the total amount of organic material (kerogen) present in the rock, expressed as a percentage by weight. Generally, the higher the total organic content, the better the potential for hydrocarbon generation. The thermal maturity of the rock is a measure of the degree to which organic matter contained in the rock has been heated over time and potentially converted into liquid and/or gaseous hydrocarbons. Thermal maturity is measured using vitrinite reflectance (Ro).

Because of the special techniques required for extraction, shale gas can be more expensive than conventional gas to extract. On the other hand, the inplace gas resource can be very large given the significant lateral extent and thickness of many shale formations. However, only a small portion of the total world resources of shale gas is theoretically producible and even less likely to be producible in a commercially viable manner. 

Sunday, September 8, 2019

Tight Gas andd Tight Oil

The terms tight oil and tight gas refer to crude oil (primarily light sweet crude oil) and natural gas, respectively, that are contained in formations such as shale or tight sandstone, where the low permeability of the formation makes it difficult for producers to extract the crude oil or natural gas except by unconventional techniques such as horizontal drilling and hydraulic fracturing. The terms unconventional oil and unconventional gas are umbrella terms for crude oil and natural gas that are produced by methods that do not meet the criteria for conventional production. Thus, the terms tight oil and tight gas refer to natural gas trapped in organic-rich rocks dominated by shale while tight gas trapped in in sandstone or limestone formations that exhibit very low permeability and such formations may also contain condenstate. Given the low permeability of these reservoirs, the gas must be developed via special drilling and production techniques including fracture stimulation (hydraulic fracturing) in order to be produced commercially (Gordon, 2012).

Unlike conventional mineral formations containing natural gas and crude oil reserves, shale and other tight formations have low permeability, which naturally limits the flow of natural gas and crude oil. In such formations, the natural gas and crude oil are held in largely unconnected pores and natural fractures. Hydraulic fracturing is the method commonly used to connect these pores and allow the gas to flow. The process of producing natural gas and crude oil from tight deposits involves many steps in addition to hydraulic fracturing, all of which involve potential environmental impacts (Speight, 2016b). 

Hydraulic fracturing is often misused as an umbrella term to include all of the steps involved in gas and oil production from shale formations and tight formations. These steps include road and well-pad construction, drilling the well, casing, perforating, hydraulic fracturing, completion, production, abandonnment, and reclamation. 

Tight sandstone formations and shale formations are heterogeneous and vary widely over relatively short distances. Thus, even in a single horizontal drill hole, the amount of gas or oil recovered may vary, as may recovery within a field or even between adjacent wells. This makes evaluation of tight plays (a play is a group of fields sharing geological similarities where the reservoir and the trap control the distribution of oil and gas). Because of the variability of the reservoirs- even reservoirs within a play- is different, decisions regarding the profitability of wells on a particular lease are difficult. Furthermore, the production of crude oil from tight formations requires that at least 15-20% v/v of the reservoir pore space is occupied by natural gas to provide the necessary reservoir energy to drive the oil toward the borehole; tight reservoirs which contain only oil cannot be economically produced (US EIA, 2013) 

In tight shale reservoirs and other tight reservoirs, there are areas known as sweet spots which are preferential targets for drilling and releasing the gas and oil. In these areas, the permeability of the formation is significantly higher than the typical permeability of the majority of the formations. The occurence of a sweet spot and the higher permeability may often result from open natural fractures, formed in the reservoir by natural stresses, which results in the creation of a dense pattern of fractures. Such fractures may have reclosed, filled in with other materials, or may still be open. However, a well that can be connected through hydraulic fracturing to open natural fracture systems can have a significant flow potential. 

Gas Hydrate

Methane hydrates is a resource in which a large amount of methane is trapped within a crystal structure of water, forming a solid similar to ice (Kvenvolden, 1995).. 

Natural gas hydrates are solids that form from a combination of water and one or more hydrocarbon or non-hydrocarbon gases. In physical appearance, gas hydrates resemble packed snow or ice. In a gas hydrate, the gas molecules (such as methane, hence the methane hydrates) are trapped within a cage-like crystal structure composed of water molecules. Gas hydrates are stable only under spesific conditions of pressure and temperature. Under the appropriate pressure, they can exist at temperatures significantly above the freezing point of water.  The maximum temperature at which gas hydrate can exist depends on pressure and gas composition. For example, methane plus water at 600 psia forms hydrate at 5 degree C, while at the same pressure, methane with 1% v/v propane forms a gas hydrate at 9.4 degree C. Hydrate stability can also be influenced by other factors, such as salinity (Edmonds et al, 1996).

Thursday, September 5, 2019

Fractured Reservoirs

  • Fractured reservoirs are reservoirs in which production and recovery is influenced to a greater or lesser extent by fractures. They can be subdivided into four different types (cf. Nelson , 2001; Allan & Qing Sun , 2003)
  • The variability in fracture network interconnectedness, and in the architecture and properties of the matrix, are the basic reasons that fractured reservoirs show a large variety of behaviors during hydrocarbon production. These large uncertainties make the appraisal, development and management of fractured reservoirs difficult. Failure to asses uncertainties properly leads to missed opportunities and low hydrocarbon recovery.
  • The special nature of fractured reservoirs lies in the interaction between, the (relatively) high pore volume , low permeability matrix (the storage domain) and the low pore volume, high permeability fracture system (the flow domain). This interaction is a function of matrix architecture and fracture network geometry, but also the mechanisms and physical processes that control the transfer of hydrocarbons from the matrix to the fracture network. The initial and developing stress state and the presence or absence of an aquifer also influence performance. 

Thursday, August 29, 2019

Coalbed Methane

Natural gas is often located in the same reservoir as with crude oil, but it can also be found trapped in gas reservoirs and within coal seams. The occurence of methane in coal seams is not a new discovery and methane (called firedamp by the miners because of its explosive nature) was known to coal miners for at least 150 years (or more) before it was rediscovered and developed as coalbed methane (Speight, 2013b). The gas occurs in the pores and cracks in the coal seam and is held there by underground water pressure. To extract the gas, a well is drilled into the coal seam and the water is pumped out (dewatering) which allows the gas to be released from the coal and brought to the surface.

Coalbed methane (sometime referred to as coalmine methane) is a generic term for the methane found in most coal seams. 

Coalbed methane is a gas formed as part of the geological process of coal generation and is contained in varying quantities within all coal. Coalbed methane is exceptionally pure compared to conventional natural gas, containing only very small proportions of higher molecular weight hydrocarbons such as ethane and butane and other gases (such as hydrogen sulfide and carbon dioxide). Coalbed gas is over 90% methane and, subject to gas composition, may be suitable for introduction into a commercial pipeline with little or no treatment (Rice, 1993; Speight, 2007).  Methane within coalbeds is not structurally trapped by overlying geologic strata, as in the geologic environments typical of conventional gas deposits. Only a small amount (on the order 5-10% v/v) of the coalbed methane is present as free gas within the joints and cleats of coalbeds. Most of the coalbed methane is contained within the coal itself (adsorbed to the sides of the small pores in the coal). 

As the coal forms, large quantities of methane-rich gas are produced and subsequently adsorbed onto (and within) the coal matrix. Because of its many natural cracks and fissures, as well as the porous nature , coal in the seam has a large internal surface area and can store much more gas than a conventional natural gas reservoir of similar rock volume. If a seam is disturbed, either during mining or by drilling into it before mining, methane is released from the surface of the coal. This methane then leaks into any open spaces such as fractures in the coal seam. In these cleats, the coalmine methane mixes with nitrogen and carbon dioxide (CO2). 

Boreholes or wells can be drilled into the seams to recover the methane. Large amounts of coal are found at shallow depths, where wells to recover the gas are relatively easy to drill at a relatively low cost. At greater depths, increased pressure may have closed the cleats, or minerals may have filled the cleats over time, lowering permeability and making it more difficult for the gas to move through the coal seam. Coalbed methane has been a hazard since mining began. To reduce any danger to coal miners, most effort is addresed at minimizing the presence of coalbed in the mine, predominantly by venting it to the atmosphere. 

In coalbeds (coal seams), methane (the primary of natural gas) is generally adsorbed to the coal rather than contained in the pore space or structurally trapped in the formation. Pumping the injected and native water out of the coalbeds after fracturing serves to depressurize the coal, thereby allowing the methane to desorb and flow into the well and to the surface. Methane has traditionally posed a hazard to underground coal miners, as the highly flammable gas is released during mining activities. Otherwise inaccessible coal seams can also be tapped to collect this gas, known as coalbed methane, by employing similar well-drilling and hydraulic fracturing techniques as are used in shale gas extraction.

The primary (or natural) permeability of coal is very low, typically ranging from 0.1 to 30 mD and, because coal is very weak (low modulus) material and cannot take much stress without fracturing, coal is almost always highly fractured and cleated. The resulting network of fractures commonly gives coalbeds a high secondary permeability (despite coal's typically low permeability). Groundwater, hydraulic-fracturing fluids, and methane gas can more easily flow through the network of fractures.  Because hydraulic fracturing generally enlarges preexisting fractures in addition to creating new fractures, this network of natural fractures is very important to the extraction of methane from the coal.

The gas from coal seams can be extracted by using technologies that are similar to those used to produce conventional gas, such as using wellbores. However, complexity arises from the fact that the coal seams are generally low permeability and tend to have a lower flow rate (or permeability) than  conventional gas systems, gas is only sourced from close to the well and as such a higher density of wells is required to develope a coalbed methane resource as an unconventional resource (such as tight gas) than a conventional gas resource. 

Technoogies such as horizontal and multilateral drilling with hydraulic fracturing are sometimes used to create longer, more open channels that enhance well productivity but not all coal seam gas wells require application of this technique. Water present in coal seam, either naturally occuring or introduced during the fracturing operation, is usually removed to reduce the pressure sufficiently to allow the gas to be released, which leads to additional operational requirements, increased investment, and environmental concerns. 

Natural Gas Condensate

Natural Gas condensate (gas condensate, natural gasoline) is a low-density low-viscosity mixture of hydrocarbon liquids that may be present as gaseous components under reservoir conditions and which occur in the raw natural gas produced from natural wells. The constituents of condensate separate from the untreated (raw) gas if the temperature is reduced to below the hydrocarbon dew point temperature of the raw gas. Briefly, the dew point is the temperature to which a given volume of gas must be cooled, at constant barometric pressure, for vapor to condense into liquid. Thus, the dew point is the saturation point. 

On a worldwide scale, there are many gas-condensate reservoir and each has its own unique gas-condensate composition. However, in general, gas condensate has a spesific gravity on the order of ranging from 0.5 to 0.8 and is composed of hydrocarbons such as propane, butane, pentane, hexane, heptane and even octane, nonane and decane in some cases. In addition, the gas condensate may contain additional impurities such as hydrogen sulfide, thiols (mercaptans, RSH), carbon dioxide, cyclohexane (C6H12), and low molecular weight aromatics such as benzene (C6H6) , toluene (C6H5CH3), etc.

When condensation occurs in the reservoir, the phenomenon known as condensate blockage can halt flow of the liquids to the wellbore. Hydraulic fracturing is the most common mitigating technology in siliciclastic reservoirs (reservoirs composed of clastic rocks), and acidizing is used in carbonate reservoirs (Speight, 2016a). Briefly, clastic rocks are composed of fragments, or clasts, of preexisting minerals and rock. A clast is a fragment of geological detritus, chunks, and smaller grains of rock broken off other rocks by physical weathering. Geologist use the term clastic with reference to sedimentary rocks as well as to particles in sediment transport whether in suspension or as bed load, and in sedimentary deposits. 

In addition, production can be improved with less drawdown in the formation. For some gas-condensate fields, a lower drawdown means single-phase production above the dew point pressure can be extended for a longer time. However, hydraulic fracturing does not generate a permanent conduit past a condensate saturation buildup area. Once the pressure drops below the dew point, saturation will increase around the fracture, just as it did around the wellbore. Horizontal or inclined wells are also being used to increase contact area within formations.